Capital expenditures are expected to be $295 to $345 million, a decrease of 57% to 63% from 2014, with 60% to 65% of the expenditures being incurred during the first half of the year.

Drilling and completion capital expenditures, which will be focused on the Upper Eagle Ford, are expected to be $270 to $310 million.

Pipeline, gathering, facilities, seismic and other capital expenditures are expected to be $10 to $15 million.

Lease acquisition capital expenditures are expected to be $15 to $20 million.

We expect drilling and completion capital expenditures to range between $6.0 and $7.5 million per well for wells with two strings of casing, assuming 15 to 25 frac stages, and between $6.5 and $10.5 million per well for 3-string wells, assuming 12 to 33 frac stages. We expect 2015 drilling and completion costs to decrease from 2014 as a result of:

A decrease in the number of frac stages per well from an average of 26.5 stages during 2014 to an average of 22 stages in 2015, with the distance between stages increasing from 225 feet to 250 feet.

A reduction in the amount of proppant per stage to approximately 300,000 lbs. from an average of approximately 360,000 lbs. in 2014.

A decrease of 10% to 20% in completion costs over 2014 levels as a result of renegotiated service sector costs, as well as the adjustments to the completion design as explained above.

An ongoing improvement in operational execution of the drilling and completion program.

Production

Production is expected to be approximately 8.7 to 9.6 million barrels of oil equivalent (MMBOE), or 23,800 to 26,200 barrels of oil equivalent per day (BOEPD), an increase of approximately 10% to 20% over 2014.

2015 crude oil production guidance is 5.0 to 5.5 million barrels, or 13,800 to 15,100 barrels of oil per day (BOPD), an increase of approximately 10% to 18% over 2014 and an increase of 6% to 15% over the fourth quarter 2014.

Production in the first quarter of 2015 is expected to range between 23,500 and 25,500 BOEPD, an increase of 10% to 20% over the fourth quarter 2014.

These estimates are meant to provide guidance only and are subject to revision as our operating environment changes.

Management Comment

H. Baird Whitehead, President and Chief Executive Officer, stated, "As we have significantly improved upon our operational execution, our focus in 2015 is to high grade our drilling program to pursue the best economic returns across our Eagle Ford asset base while maintaining healthy levels of financial liquidity. Given current lower oil prices, we intend to operate three to four drilling rigs during 2015.

Whitehead added, "During this challenging environment, we are taking a disciplined approach to deploying capital in order to achieve year-over-year production growth and maintain a relatively flat production profile throughout the year. We are being vigilant in our pursuit of cost reductions and believe further cost decreases this year are likely as additional service sector costs are renegotiated. Furthermore, we also have significant oil hedges in place which allow us to protect cash flow below a $90 oil price on 80% to 90% of our expected oil production.

"We are encouraged by our recent results and especially by our breakthrough in the Upper Eagle Ford, to which we intend to devote a majority of our drilling capital during 2015. Recently, we drilled our first Upper Eagle Ford well in the Peach Creek area near Fayette County and are very excited with its early results, along with the early results of the adjacent two Lower Eagle Ford wells. Compared to the Lower Eagle Ford, the Upper Eagle Ford, in general, has similar initial production rates but higher expected reserves due to its lesser initial production decline.

Whitehead concluded, "We believe that we have a premium position and are a leading operator in the highest return oil shale play in the U.S."

Eagle Ford Shale Operational Update

Fourth Quarter 2014 Update

Fourth quarter production from our Eagle Ford operations was 17,459 BOEPD. Approximately 73% of our fourth quarter Eagle Ford production was from crude oil, 14% was from NGLs and 13% was from natural gas.

Below are the results and statistics for Eagle Ford wells over the past seven quarters: (1)

Averages

Peak Gross DailyProduction Rates(2)

30-Day Average Gross Daily Production Rates(2)

Gross/ Net Wells

Lateral Length

Frac Stages

Proppant

OilRate

EquivalentRate

Oil
Percentage

OilRate

EquivalentRate

Oil
Percentage

Feet

lbs.

BOPD

BOEPD

BOPD

BOEPD

Time Period

2013 - 2nd quarter

12 / 6.9

5,767

23.9

5,368,204

1,196

1,389

86%

689

825

84%

2013 - 3rd quarter

7 / 3.6

6,508

26.1

7,240,340

1,547

1,780

87%

1,010

1,176

86%

2013 - 4th quarter

11 / 5.3

6,291

26.8

8,700,229

1,442

1,657

87%

1,024

1,200

85%

2014 - 1st quarter

13 / 9.7

6,008

25.8

8,014,879

1,192

1,493

80%

717

868

83%

2014 - 2nd quarter

24 / 14.4

5,462

25.1

9,179,233

1,175

1,469

80%

726

896

81%

2014 – 3rd quarter

15 / 7.3

6,052

27.7

10,418,905

1,179

1,407

84%

720

858

83%

2014 – 4th quarter(3)

26 / 19.0

5,836

27.3

10,013,032

871

1,226

71%

632

937

74%

Totals and averages(3)

108 / 66.3

5,886

26.2

8,814,081

1,158

1,435

81%

753

938

80%

Operating Area

Upper Eagle Ford

16 / 14.6

5,881

27.1

10,217,420

747

1,217

61%

616

1,009

61%

Shiner -- "Beer Six Pack"

32 / 15.0

5,928

26.8

9,643,637

1,338

1,622

82%

842

1,244

83%

Rock Creek / Bozka

10 / 5.1

5,958

27.6

9,890,733

1,366

1,644

83%

1,026

1,244

82%

Peach Creek

28 / 13.1

6,293

26.9

8,114,642

1,291

1,421

91%

817

901

91%

Shiner - Mod. GOR

9 / 7.1

5,395

22.9

7,123,231

1,116

1,368

82%

625

768

81%

Shiner - High GOR

13 / 11.4

5,195

23.2

6,893,792

803

1,159

69%

466

661

70%

Totals and averages(3)

108 / 66.3

5,886

26.2

8,814,081

1,158

1,435

81%

753

938

80%

(1) Excludes non-operated wells, "shallow" wells, defined as wells whose vertical depth, including the "curve," is 10,500 feet or less, wells with less than 20 frac stages and one Upper Eagle Ford well that had operational issues, as previously disclosed. GOR is defined as gas-oil ratio (Mcf per barrel of oil).

(2) Wellhead rates only; the natural gas associated with these wells is yielding between 135 and 155 barrels of NGLs per million cubic feet.

(3) 30-day information is available for 20 wells since the end of the third quarter of 2014 and for 102 wells since April 1, 2013. Includes wells turned in line after December 31, 2014.

Since the end of the third quarter of 2014, we have turned in line 26 (19.0 net) operated wells, excluding two wells with less than 20 frac stages and one Upper Eagle Ford well that had an operational issue which was subsequently remediated very late in 2014. As a group, these 26 wells had an average IP rate of 1,226 BOEPD over an average of 27.3 frac stages, with 71% of production from crude oil. Of these 26 wells, 20 wells with sufficient production history had a 30-day average rate of 937 BOEPD, with 74% of production from crude oil. The average amount of proppant per stage for these 26 wells was approximately 372,000 pounds. Even though the average IP rate decreased from the third quarter, the 30-day average rate actually increased over this same timeframe and is likely attributable to the relatively high 30‑day averages for Upper Eagle Ford wells (12 Upper Eagle Ford wells are included in this grouping).

Our excellent overall results observed to date in the Upper Eagle Ford continue to demonstrate the significant potential we believe this zone has across our acreage position. As we complete additional Upper Eagle Ford wells and test our acreage, the production results of those wells seem to substantiate that the Upper and Lower Eagle Ford are acting as separate reservoirs. Since March 2014, we have completed and turned in line 17 Upper Eagle Ford wells, including the one well that had an operational issue. The average IP rate for the 16 wells that did not encounter an operational issue was 1,217 BOEPD (61% oil) and the average 30-day rate for 14 of these 16 wells with sufficient production history was 1,009 BOEPD (61% oil).

The Welhausen #A2H was turned in line in March 2014 and has cumulative production of 208,792 barrels of oil equivalent (BOE) (52% oil), or an average of 640 BOEPD, over 326 producing days, along with a 60-day rate of 1,519 BOEPD, a 30-day rate of 1,767 BOEPD and an IP rate of 2,165 BOEPD. The Martinsen #2H was turned in line in May 2014 and has cumulative production of 221,778 BOE (58% oil), or an average of 783 BOEPD, over 283 producing days, along with a 60-day rate of 1,149 BOEPD, a 30-day rate of 1,238 BOEPD and an IP rate of 1,360 BOEPD. Clearly, although preliminary, the early performance and lower initial rates of decline for the Upper Eagle Ford wells are an improvement over what we typically see in the Lower Eagle Ford. The internal estimated ultimate reserves for these wells averaged approximately 717 MBOE, with a range of 388 to 1,231 MBOE. Due to these excellent results, we plan to devote a significant portion of our 2015 capital expenditures to drilling additional Upper Eagle Ford wells. We now believe that approximately 80% of our net acreage is prospective in the Upper Eagle Ford with approximately 1,850 prospective Upper Eagle Ford drilling locations based on internal estimates.

Year-End 2014 Proved Reserves Highlights

Proved oil and gas reserves of 114.8 million MMBOE.

Oil reserves were 69.0 million barrels (MMBbls), or 60% of the total.

Natural gas liquids (NGLs) reserves were 19.2 MMBbls, or 17% of the total.

Natural gas reserves were 159.3 Bcf (26.5 MMBOE), or 23% of the total.

Proved developed reserves were 45.9 MMBOE, and proved undeveloped reserves were 68.9 MMBOE.

Proved developed reserves in the Eagle Ford increased from 21.9 MMBOE at year-end 2013 to 27.6 MMBOE at year-end 2014, or a 26% increase.

Total proved reserves were 94.1 MMBOE in the Eagle Ford, 13.7 MMBOE in East Texas and 6.8 MMBOE in Oklahoma.

Total proved reserves in the Eagle Ford increased 24% from 75.6 MMBOE at year-end 2013.

The pre-tax present value of estimated future net cash flows from proved reserves, discounted at 10% (PV‑10), which is a non-GAAP (generally accepted accounting principles) financial measure, and assuming an oil price of $94.99 per barrel and a natural gas price of $4.35 per MMBtu (million British thermal units), was $1.5 billion, of which $1.0 billion is associated with proved developed reserves.

Based on internal estimates, proved and probable reserves in the Eagle Ford as of year-end 2014 were 1,093 MMBOE with a pretax PV-10 of approximately $3.0 billion, assuming an oil price of $60 per barrel and a natural gas price of $4.00 per MMBtu.

The definition of non-GAAP PV-10 and reconciliation of this non-GAAP financial measure to a GAAP-based measure appears later in this release.

Fourth Quarter 2014 Operational Results

Production

As shown in the table below, total production in the fourth quarter of 2014 was 21,308 BOEPD, compared to 20,874 BOEPD in the third quarter of 2014, pro forma to exclude production from Mississippi properties sold in July 2014 and volumes associated with a settlement of litigation in the Mid-Continent. In December 2014, our average production was approximately 22,400 BOEPD, while January 2015 production averaged approximately 25,200 BOEPD, of which approximately 22,000 BOEPD was associated with the Eagle Ford. The levels of production in the fourth quarter were approximately 5,500 BOEPD lower than expected. This was due primarily to timing related to shut-in wells resulting from offset frac activity and delays in turning in line new Eagle Ford completions (approximately 4,700 BOEPD) and mechanical issues with Eagle Ford wells, net of improved performance of other Eagle Ford wells (approximately 800 BOEPD). Most of the Eagle Ford wells which had timing or mechanical issues subsequently have been completed, turned in line or brought back online.

Total and Daily Equivalent Production for the Three Months Ended

Region / Play Type

Dec. 31,2014

Sept. 30,2014

Jun. 30,2014

Mar. 31,2014

Dec. 31,2014

Sept. 30,2014

June 30,2014

Mar. 31,2014

(in MBOE)

(in BOEPD)

Eagle Ford Shale

1,606

1,557

1,421

1,328

17,459

16,929

15,618

14,761

East Texas

201

208

220

215

2,181

2,257

2,417

2,394

Mid-Continent(4)

147

258

161

174

1,604

2,802

1,770

1,931

Mississippi / Other

6

66

180

184

64

719

1,981

2,047

Totals

1,960

2,089

1,983

1,902

21,308

22,706

21,786

21,133

Pro Forma Totals(5)

1,960

1,920

1,809

1,724

21,308

20,874

19,872

19,153

Note - Numbers may not add due to rounding. MBOE equals one thousand barrels of oil equivalent.

(4) Third quarter 2014 Mid-Continent volumes included approximately 109 MBOE (1,180 BOEPD) related to the settlement of litigation.

(5) Pro forma to exclude volumes from Mississippi properties sold in July 2014 and the third quarter 2014 Mid-Continent adjustment.

Explanation of Non-GAAP PV-10 Value

Non-GAAP PV-10 value is the estimated future net cash flows from estimated proved reserves discounted at an annual rate of 10 percent before giving effect to income taxes. The standardized measure is the after-tax estimated future cash flows from estimated proved reserves discounted at an annual rate of 10 percent, determined in accordance with generally accepted accounting principles (GAAP). We use non-GAAP PV-10 value as one measure of the value of our estimated proved reserves and to compare relative values of proved reserves among exploration and production companies without regard to income taxes. We believe that securities analysts and rating agencies use PV-10 value in similar ways. Our management believes PV-10 value is a useful measure for comparison of proved reserve values among companies because, unlike standardized measure, it excludes future income taxes that often depend principally on the characteristics of the owner of the reserves rather than on the nature, location and quality of the reserves themselves. We cannot reconcile PV-10 value to the standardized measure at this time because final income tax information for the year ended December 31, 2014 is not yet available. The standardized measure will be provided in our forthcoming Form 10-K for the year ended December 31, 2014 to be filed with the Securities and Exchange Commission (SEC).

Fourth Quarter and Full-Year 2014 Conference Call

A conference call and webcast, during which management will discuss fourth quarter 2014 financial and operational results, is scheduled for Thursday, February 26, 2015 at 10:00 a.m. ET. Prepared remarks by H. Baird Whitehead, President and Chief Executive Officer, will be followed by a question and answer period. Investors and analysts may participate via phone by dialing toll free 1-877-316-5288 (international: 1-734-385-4977) five to 10 minutes before the scheduled start of the conference call (use the conference code 59449147), or via webcast by logging on to our website, www.pennvirginia.com, at least 15 minutes prior to the scheduled start of the call to download and install any necessary audio software. A telephonic replay will be available for two weeks beginning approximately 24 hours after the call. The replay can be accessed by dialing toll free 1-855-859-2056 (international: 1-404-537-3406) and using the replay code 59449147. In addition, an on-demand replay of the webcast will also be available for two weeks at our website beginning approximately 24 hours after the webcast.

Penn Virginia Corporation (NYSE:PVA) is an independent oil and gas company engaged in the exploration, development and production of oil, natural gas liquids and natural gas in various domestic onshore regions of the United States, with a primary focus in the Eagle Ford Shale in south Texas. For more information, please visit our website at www.pennvirginia.com.

Certain statements contained herein that are not descriptions of historical facts are "forward-looking" statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Because such statements include risks, uncertainties and contingencies, actual results may differ materially from those expressed or implied by such forward-looking statements. These risks, uncertainties and contingencies include, but are not limited to, the following: the volatility of commodity prices for oil, NGLs and natural gas; our ability to develop, explore for, acquire and replace oil and natural gas reserves and sustain production; our ability to generate profits or achieve targeted reserves in our development and exploratory drilling and well operations; any impairments, write-downs or write-offs of our reserves or assets; the projected demand for and supply of oil, NGLs and natural gas; reductions in the borrowing base under our revolving credit facility; our ability to contract for drilling rigs, supplies and services at reasonable costs; our ability to obtain adequate pipeline transportation capacity for our oil and gas production at reasonable cost and to sell the production at, or at reasonable discounts to, market prices; the uncertainties inherent in projecting future rates of production for our wells and the extent to which actual production differs from estimated proved oil and natural gas reserves; drilling and operating risks; our ability to compete effectively against other oil and gas companies; our ability to successfully monetize select assets and repay our debt; leasehold terms expiring before production can be established; environmental obligations, costs and liabilities that are not covered by an effective indemnity or insurance; the timing of receipt of necessary regulatory permits; the effect of commodity and financial derivative arrangements; our ability to maintain adequate financial liquidity and to access adequate levels of capital on reasonable terms; the occurrence of unusual weather or operating conditions, including force majeure events; our ability to retain or attract senior management and key technical employees; counterparty risk related to their ability to meet their future obligations; compliance with and changes in governmental regulations or enforcement practices, especially with respect to environmental, health and safety matters; uncertainties relating to general domestic and international economic and political conditions; and other risks set forth in our filings with the SEC.

Additional information concerning these and other factors can be found in our press releases and public periodic filings with the SEC. Many of the factors that will determine our future results are beyond the ability of management to control or predict. Readers should not place undue reliance on forward-looking statements, which reflect management's views only as of the date hereof. All subsequent written and oral forward-looking statements attributable to PVA or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements. We undertake no obligation to revise or update any forward-looking statements, or to make any other forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable law.

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